Natural gas is a clean-burning hydrocarbon fuel that produces less “greenhouse gases” upon total combustion than that produced from combustion of heavier hydrocarbons such as gasoline, diesel, fuel oil and coal. As a result, natural gas has been identified as an “environmentally friendly” fuel. In recent years, demand for natural gas has been outpacing wellhead supplies that are available for direct connection and delivery into the gas pipeline transport and distribution systems throughout the world, and particularly so within the United States and Europe. As a result, natural gas marketers, pipeline transporters, distributors and power utilities are turning to Liquefied Natural Gas (LNG) to supplement their traditional natural gas supply. Pacific Rim demand for LNG is also increasing at a remarkable rate with accelerating LNG demand projected for Korea, Japan, China and India.
LNG is immerging as an attractive alternative fuel for the transportation and vehicle fuel markets. New technology and government-sponsored programs have helped LNG to become a viable alternative to the more conventional forms of fuel. Both LNG and CNG are anticipated to capture a larger share of this market in the next decade displacing gasoline and diesel fuels. LNG is primarily liquefied methane containing varying quantities of ethane, propane and butanes with trace quantities of pentanes and heavier hydrocarbon components. When stored or transported at or near atmospheric pressure, LNG is a very cold liquid with temperatures ranging between −245° F. to −265° F. dependent upon its composition.
Certain commercial quality specifications must be met when LNG enters the commercial marketplace. Natural gas pipeline and power utility companies, for example, specify in their commercial contracts that natural gas delivered into their facilities must comply with heating value or in some cases, Wobbie Index quality specifications as well as hydrocarbon dew point parameters. When LNG is distributed and used as fuel to power busses, fleet vehicles, private vehicles or other equipment, it must comply with certain quality specifications to assure the characteristics of the fuel yields clean, complete and total combustion in the customer's engine. LNG can also serve as a source of natural gas for making Compressed Natural Gas (CNG) used in the fuels market and when this is the case, CNG quality specification will apply to the LNG.
Some LNG sources contain more ethane and heavier hydrocarbons than others depending on the composition of the natural gas used in making the LNG. Depending upon the quantity of ethane and heavier hydrocarbons contained in the LNG, the LNG may have to be processed and conditioned to reduce the ethane and heavier hydrocarbon content in order to meet the specific commercial quality specifications for its use.
From time to time, the liquid product price of ethane, propane, butanes and heavier hydrocarbon reflects a premium over that which would be realized if left in the LNG and sold at prevailing natural gas prices. Therefore, extraction of these products from LNG can be commercially attractive improving the overall revenue realization of the LNG source.
Ethane and heavier hydrocarbons have for many years been extracted and recovered from raw natural gas produced from gas wells and produced in association with crude oil production. Gas processing facilities of various designs and configurations including the application of turbo-expanders, mechanical refrigeration, lean oil absorption, adsorption using desiccants and combinations thereof have been used for this purpose. The most common prior technology for recovery of ethane and heavier hydrocarbons (NGL) from LNG is based upon the concept of pumping the LNG to high pressure, vaporizing the LNG and processing the resulting gas using traditional gas processing techniques with the conventional cryogenic turbo-expander and/or cryogenic J-T expansion processes being the most widely used. This practice does not capture and fully utilize the benefits of the cryogenic conditions available from the LNG.
There are three other known processes for recovery of NGL from LNG that are disclosed in U.S. Pat. Nos. 5,114,451, 5,588,308, and 6,604,380 that makes some use of the beneficial cryogenic conditions and properties of LNG.
U.S. Pat. No. 5,114,451 discloses a process for recovery of NGL from LNG where the LNG feed is warmed by cross exchange of heat from a warm gas stream being a recompressed overhead recycle stream from the fractionation unit (commonly referred to as a demethanizer). The NGL product is recovered as a liquid product from the bottom of the demethanizer. The send-out gas (the overhead vapor from the demethanizer), however, must be heated and compressed prior to delivery to the pipeline system. Compression and heating adds to the capital costs and fuel consumption of the process.
U.S. Pat. No. 5,588,308 discloses a process that recovers NGL by cooling and partial condensation of purified natural gas feed wherein a portion of the necessary feed cooling and condensation duty is provided by expansion and vaporization of condensed feed liquid after methane stripping, thereby yielding an NGL product in gaseous form. In the market place, NGL is sold and transported as a liquid product. Additional cooling and compression are required to make a liquid NGL product that adds to the capital cost and fuel consumption for making the final NGL product.
U.S. Pat. No. 6,604,380 discloses a process for recovery of NGL from LNG using a portion of the LNG feed, without heating or other treatment, as an external reflux during separation. A fractionation column is used in the process to recover an NGL liquid product from the bottom of the column with the overhead vapor product being the methane-rich residue gas which is subsequently compressed, re-liquefied, pumped, vaporized and sent to the receiving pipeline. This process, however, requires that the entire overhead vapor product stream from the fractionation column be compressed by a low head compressor in order to re-liquefy. The compression required for the process is a low head (75 to 115 psi), but requires the entire send-out gas stream to be compressed. If, for example, the facility is designed for a capacity to handle say 1,000 million standard cubic feet per day (MMscfd) of send-out gas, the compression brake horsepower (Bhp) could be on the order of 5 to 7 Bhp/MMscfd requiring a 5,000 Bhp to 7,000 Bhp compressor. This compressor and its associated fuel consumption add to the capital cost and operating expense for the facility.